L-MT-23-036, Subsequent License Renewal Application Response to Request for Additional Information Set 2 and Supplement 6

Subsequent License Renewal Application Response to Request for Additional Information Set 2 and Supplement 6

ML23248A474
Person / Time
Site:	Monticello
Issue date:	09/05/2023
From:	Hafen S Northern States Power Company, Minnesota, Xcel Energy
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
L-MT-23-036
Download: ML23248A474 (1)

Text

(l Xcel Energy 2807 West County Road 75 Monticello, MN 55362 September 05, 2023 L-MT-23-036 10 CFR 54.17 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Monticello Nuclear Generating Plant Docket No. 50-263 Renewed Facility Operating License No. DPR-22 Subsequent License Renewal Application Response to Request for Additional Information Set 2 and Supplement 6

References:

1) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant Docket No. 50-263, Renewal License Number DPR-22 Application for Subsequent Renewal Operating License dated January 9, 2023, ML23009A353

2) Email from the NRC to Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy, Monticello SLRA - Request for Additional Information - Set 1 dated July 19, 2023, ML23200A350 and ML23200A351

3) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant - Subsequent License Renewal Application Response to Request for Additional Information Set 1 dated August 15, 2023, ML23227A175

4) Email from the NRC to Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy, Monticello SLRA - Request for Additional Information - Set 2 dated August 7, 2023, ML23219A107 and ML23219A108

5) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant Subsequent License Renewal Application Supplement 1 dated April 3, 2023, ML23094A136

6) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant Subsequent License Renewal Application Supplement 2 dated June 26, 2023, ML23177A218

Document Control Desk L-MT-23-036 Page 2

7) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant Subsequent License Renewal Application Supplement 3 dated July 11, 2023, ML23193B026

8) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant Subsequent License Renewal Application Supplement 4 and Responses to Request for Con"rmation of Information - Set 1 dated July 18, 2023, ML23199A154

9) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant Subsequent License Renewal Application Supplement 5 dated August 28, 2023, ML23240A695 Northern States Power Company, a Minnesota corporation, doing business as Xcel Energy hereafter "NSPM", is submitting responses to requests for additional information (RAIs) and a supplement to the Subsequent License Renewal Application, listed in Reference 1.

RAI Set 1 was issued by the NRC in Reference 2 and responded to in Reference 3. Additional RAIs were issued by the NRC as Set 2 on August 7, 2023 (Reference 4). The responses to RAI Set 2 are provided in the Enclosures of Attachment 1. Any RAI responses that required revisions to the SLRA are marked up in accordance with the paragraph below that discusses changes to the SLRA.

Clarifying information regarding Tables 4.2.3-1 and 4.2.3-2 and an updated reference was provided in Supplement 1, listed in Reference 5. Clari"cations to sections of the SLRA discussed in the breakout audits occurring April through June of 2023 were provided in Supplements 2, 3, 4, and 5, listed in References 6, 7, 8, and 9, respectively. Note that Supplement 3 (Reference 7) did not make any changes to the SLRA. Additional clari"cations discussed in the breakout audits occurring April through June of 2023 are being provided in Supplement 6. The supplement is provided in the Enclosure of Attachment 2.

In the enclosures, changes are described along with the aected section(s) and page number(s) of the docketed SLRA (Reference 1) where the changes are to apply. For clarity, revisions to the SLRA are provided with deleted text by strikethrough and inserted text by bold red underline. Changes incorporated from previous RAIs and supplements are provided by bold, black font and noted in the enclosure.

Summary of Commitments This letter makes no new commitments. Revisions to existing commitments are explained in the enclosures. Commitments 18 and 30 include revisions.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on September~ 2023.

~ en Site Vice President, Monticello Nuclear Generating Plant Northern States Power Company - Minnesota cc: Administrator, Region Ill, USNRC Project Manager, Monticello, USNRC Resident Inspector, Monticello, USNRC Minnesota Department of Commerce

Document Control Desk L-MT-23-036 Page 1 Attachment 1 Enclosures Index Enclosure Subject No.

01 RAI B.2.3.21-1 02 RAI B.2.3.27-1 03 RAI B.2.3.27-2 04 RAI B.2.3.15-1 05 RAI B.2.3.15-2 06 RAI 4.3.2-2 1

RAI B.2.3.21-1

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 1 of 4 RAI B.2.3.21-1 Regulatory Basis:

10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background:

SLRA Table 3.3.2-9, Fire System - Summary of Aging Management Evaluation, states that loss of material due to selective leaching for gray cast iron piping exposed to soil will be managed by the Selective Leaching program.

SLRA Section B.2.3.21, Selective Leaching, states the following:

• Each of the one-time and periodic inspections for the various material and environment populations comprises a 3 percent sample or a maximum of 10 components.

• For raw water, waste water, and soil environments, the AMP includes opportunistic and periodic visual inspections of selected components that are susceptible to selective leaching, coupled with mechanical examination techniques. Destructive examinations of components to determine the presence of and depth of dealloying through-wall thickness are also conducted.

The plant-specific operating experience summary in SLRA Section B.2.3.21 does not describe any operating experience or results of inspections related to gray cast iron piping exposed to soil.

NUREG-2222, Disposition of Public Comments on the Draft Subsequent License Renewal Guidance Documents NUREG-2191 and NUREG-2192, states the following regarding the staffs basis for reducing the extent of inspections for selective leaching during the subsequent period of extended operation (i.e., 3 percent with a maximum of 10 components per GALL-SLR guidance) when compared to the extent of inspections for selective leaching during the initial period of extended operation (i.e., 20 percent with a maximum of 25 components per GALL Report, Revision 2 guidance):

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 2 of 4

1. Opportunistic inspections will be conducted throughout the period of extended operation whenever components are opened, buried, or submerged surfaces are exposed, whereas opportunistic inspections were not recommended in the previous version of AMP XI.M33;

2. Destructive examinations provide a more effective means to detect and quantify loss of material due to selective leaching;

3. The slow growing nature of selective leaching generally coupled with the inspections conducted prior to the initial period of extended operation provides insights into the extent of loss of material due to selective leaching that can be used in the subsequent period of extended operation;

4. The staffs review of many license renewal applications has not revealed any instances where loss of intended function has occurred due to selective leaching;

5. The staffs review of industry OE has not detected any instances of loss of material due to selective leaching, which resulted in a loss of intended function for the component; and

6. Regional inspector input (provided based on IP 71003, Post-Approval Site Inspection for License Renewal,) that selective leaching has been noted during visual and destructive inspections; however, no instances have been identified where there was the potential for loss of intended function.

The NRC issued Information Notice (IN) 2020-04, Operating Experience Regarding Failure of Buried Fire Protection Main Yard Piping, to inform the industry of operating experience involving the loss of function of buried gray cast iron fire water main yard piping due to multiple factors, including graphitic corrosion (i.e., selective leaching), overpressuration, low-cycle fatigue, and surface loads. As noted in the IN, a contributing cause to the failure of buried gray cast iron piping at Surry Power Station was the external reduction in wall thickness at several locations due to graphitic corrosion. In this instance, the thin asphalt external coating could not protect the pipe from the highly corrosive soil environment.

As amended by letter dated June 26, 2023 (ML23177A218), SLRA Section B.2.3.16, Fire Water System, states [t]he external coating of buried cast iron or ductile iron piping is a bituminous coating of either coal-tar or asphalt base approximately 1 mil [thousandth of an inch] thick.

Issue:

The recommended extent of inspections in GALL-SLR AMP XI.M33 are based on the six conditions noted by the staff in NUREG-2222. The staffs comparison to these six conditions to the Selective Leaching program at Monticello follows:

• Based on its review of SLRA Section B.2.3.21, the staff noted that opportunistic inspections and destructive examinations for selective leaching will be performed, consistent with the first and second conditions in NUREG-2222.

• Based on its review of plant-specific operating experience in SLRA Section B.2.3.21, the staff could not determine if selective leaching inspections have been conducted for gray

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 3 of 4 cast iron piping exposed to soil. Based on this observation (i.e., inspections for this material and environment combination may not have been performed prior to the initial period of extended operation), the third condition in NUREG-2222 may not be met at Monticello for gray cast iron piping exposed to soil.

• The fourth, fifth, and sixth conditions in NUREG-2222 focus on the staffs review of industry operating experience not identifying any instances of loss of material due to selective leaching which had resulted in a loss of intended function for the component.

Based on recent industry operating experience documented in IN-2020-04, the last three conditions in NUREG-2222 are no longer applicable for gray cast iron piping exposed to soil. Since these conditions are no longer applicable (i.e., there is now industry operating experience involving loss of material due to selective leaching which resulted in a loss of intended function for gray cast iron piping exposed to soil), the staff requires additional information to determine if the reduced extent of inspections in GALL-SLR AMP XI.M33 are appropriate for this material and environment combination.

The staff also noted buried gray cast iron piping at Monticello is coated with a thin external bituminous coating, which was a contributing cause to a failure of buried gray cast iron piping at Surry Power Station as documented in IN-2020-04.

Request:

Provide additional operating experience (or other technical justification) to demonstrate that the extent of inspections in GALL-SLR AMP XI.M33 (i.e., 3 percent with a maximum of 10 components) are appropriate for gray cast iron piping exposed to soil.

RAI B.2.3.21-1 Response:

Plant-specific OE documents instances of selective leaching found in components (as described in SLRA Section B.2.3.21). Plant-specific OE does not indicate the presence of selective leaching occurring on the exterior surface of buried components. Selective leaching at MNGP has only been an issue for piping exposed to raw water. As a result of industry OE documented in IN-2020-04, MNGP performed an evaluation and determined that there was only one location where piping in a saturated (wet) soil environment existed. Excavation of a section of fire protection loop piping and a hydrant in the vicinity of this area had been performed in 2017. The results of the evaluations of the excavated piping, hydrant, and their environment are summarized in SLRA Section B.2.3.21. That summary indicated that:

• external coatings were undamaged,

• threaded hardware was still usable,

• no evidence of selective leaching was found,

• soil is homogeneous with characteristics that have negligible effects on the external corrosion rates at MNGP, and

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 4 of 4

• coating and cathodic protection systems continued to provide adequate protection from corrosion degradation.

The scope of implementing procedure PEI-03.01.03, Selective Leaching Inspection, includes susceptible gray cast iron and ductile iron components exposed to raw water. Procedures PEI-03.01.03 and EWI-08.26.02, Selective Leaching Inspection Process, include components exposed to damp soil (moist soil/earth) within the population of components to be inspected for selective leaching. Procedure EWI-11.01.14, Buried Piping and Tanks Inspection, includes monitoring and inspections of buried, coated piping components within the scope of LR, including inspections for selective leaching per EWI-08.26.02 and EWI-11.01.35, Selective Leaching of Material. MNGP has not experienced loss of function due to selective leaching of buried, coated piping failures.

Selective leaching has been identified in gray cast iron valves with internal environments of raw water during inspections performed in implementation of MNGPs initial renewed license. As a result, procedures were implemented to institute opportunistic inspections for selective leaching.

After selective leaching was identified, scope expansion was utilized to perform additional inspections on susceptible components. All instances of selective leaching were identified prior to a loss of intended function and there have been no failures resulting from selective leaching.

An AMP effectiveness review was completed in March 2020. The next five-year AMP effectiveness review will take place in 2025 and will include review of the plant-specific operating experience in the 2020-2025 time frame.

This OE demonstrates that MNGP enhances the Selective Leaching AMP when necessary, through systematic and ongoing review of plant-specific OE.

Based on the plant-specific OE and effectiveness of the existing Selective Leaching AMP at MNGP, the reduced sample size for inspection of components susceptible to selective leaching in a soil environment is appropriate.

References:

1. EWI-08.26.02, Selective Leaching Inspection Process

2. PEI-03.01.03, Selective Leaching Inspection

3. EWI-11.01.14, Buried Piping and Tanks Inspection

4. EWI-11.01.35, Selective Leaching of Material Associated SLRA Revisions:

No SLRA changes have been identified as a result of this response.

2 RAI B.2.3.27-1

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 2 Page 1 of 3 RAI B.2.3.27-1 Regulatory Basis:

10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background:

As amended by letter dated June 26, 2023 (ML23177A218), SLRA Table A-3, List of SLR Commitments and Implementation Schedule, Commitment 30(e) states the following (in part):

[p]erform inspections of buried and underground piping and tanks in accordance with NUREG-2191 Table XI.M41-2 Preventive Action Category C for buried steel and stainless steel components, unless a reevaluation of future OE [operating experience] and soil conditions determines that another Preventive Action Category is more applicable. In the 10-year period prior to and during SPEO [subsequent period of extended operation] for each 10- year interval, perform buried and underground piping and tanks inspections in accordance with the Preventive Action Category C as outlined in NUREG-2191 Table XI.M41-2.

SLRA Section B.2.3.27, Buried and Underground Piping and Tanks, includes the following enhancement (in part):

[c]larify that inspections of buried and underground piping and tanks within the applicable plant systems will be conducted in accordance with NUREG-2191 Table XI.M41-2 Preventive Action Category F for buried steel and stainless steel piping, unless a reevaluation of cathodic protection performance, future OE, or soil conditions determines that another Preventive Action Category is more applicable.

Preventive Action Category C cited in GALL-SLR Report Table XI.M41-2, Inspection of Buried and Underground Piping and Tanks, is applicable to plants where the cathodic protection system has met availability and effectiveness goals.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 2 Page 2 of 3 Issue:

The staff noted the following based on its comparison of the commitment and enhancement cited above:

1. For buried steel piping, Preventive Action Category C is referenced in the commitment; however, Preventive Action Category F is referenced in the enhancement. The staff seeks clarification with respect to why different Preventive Action Categories are cited in the enhancement and commitment.

2. The staff seeks clarification with respect to why cathodic protection performance is referenced in the enhancement but not in the commitment. Preventive Action Category C is applicable to plants where the cathodic protection system has met availability and effectiveness goals.

Request:

1. Provide clarification with respect to why different Preventive Action Categories are cited in the enhancement and commitment for buried steel piping and revise the SLRA (as appropriate).

2. State the basis for not including cathodic protection performance in the commitment.

Alternatively, revise the SLRA (as appropriate) to clarify that the number of inspections for buried steel piping are based on cathodic protection performance.

RAI B.2.3.27-1 Response:

1. The correction to update the Preventive Action Category from F to C was overlooked when making the changes identified in Enclosure 06a of Reference 2 and in Enclosure 06c of Reference 1. Element 4 (Detection of Aging Effects) is revised to correct Category F to Category C as shown below.

2. Cathodic protection performance should have been included in Commitment 30e as shown in Enclosure 06a of Reference 2, and is revised as shown below. Previous changes made in Enclosure 06a of Reference 2 are shown in bold black font.

References:

1. L-MT-23-031, Monticello Nuclear Generating Plant, Docket No. 50-263, Renewed Facility Operating License No. DPR-22, Subsequent License Renewal Application Supplement 4 and Responses to Request for Confirmation of Information - Set 1, ML23199A154.

2. L-MT-23-025, Monticello Nuclear Generating Plant, Docket No. 50-263, Renewed Facility Operating License No. DPR-22, Subsequent License Renewal Application Supplement 2, ML23177A218.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 Enclosure 02 Page 3 of 3 Associated SLRA Revisions:

Table A-3, Commitment 30e on pages A-81 and A-82 is revised as follows:

No. Aging NUREG-2191 Commitment Implementation Management Section Schedule Program or Activity (Section) 30 Buried and XI.M41 e) Perform inspections of buried and No later than 6 Underground underground piping and tanks in months prior to Piping and accordance with NUREG-2191 Table the SPEO, or no Tanks XI.M41-2 Preventive Action Category C for later than the last (A.2.2.27) buried steel and stainless steel refueling outage components, unless a reevaluation of prior to the SPEO.

cathodic protection system performance, future OE, and soil Implement the conditions determines that another AMP and start 10-Preventive Action Category is more year interval applicable. In the 10-year period prior to inspections no and during SPEO for each 10-year interval, earlier than 10 perform buried and underground piping and years prior to the tanks inspections in accordance with the SPEO.

Preventive Action Category C as outlined in NUREG-2191 Table XI.M41-2. When the Commitment 30q inspections for a given material type is will be based on percentage of length and results implemented 5 in an inspection quantity of less than 10 years prior to the feet, then 10 feet of piping is inspected. If SPEO in order to the entire run of piping of that material type credit the system is less than 10 feet in total length, then the for pre-SPEO entire run of piping is inspected. inspections.

Section B.2.3.27 on page B-200 is revised as follows:

Element Affected Enhancement

4. Detection of Update MNGP BUPT AMP procedures as appropriate:

Aging Effects

• Clarify that inspections of buried and underground piping and tanks within the applicable plant systems will be conducted in accordance with NUREG-2191 Table XI.M41-2 Preventive Action Category F C for buried steel and stainless steel piping, unless a reevaluation of cathodic protection performance, future OE, or soil conditions determines that another Preventive Action Category is more applicable.

3 RAI B.2.3.27-2

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 3 Page 1 of 4 RAI B.2.3.27-2 Regulatory Basis:

10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background:

SLRA Section B.2.3.27, Buried and Underground Piping and Tanks, includes the following enhancement (in part):

[c]larify the guidance for piping inspection location selection as follows: (a) a risk ranking system software incorporates inputs that include coating type, coating condition, cathodic protection efficacy, backfill characteristics, soil resistivity, pipe contents, and pipe function During its audit, the staff reviewed SL-008367, Nuclear Management Company Monticello Nuclear Generating Plant Cathodic Protection System Evaluation Report, Revision 0 and noted pipe-to-soil potential measurements as negative as -23,921 mV with respect to a zinc reference cell between the years 1976 and 2003.

GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks, recommends a limiting critical potential of -1,200 mV to prevent damage to coatings or base metals.

Issue:

Based on its observation during the audit noted above, the staff seeks clarification with respect to why cathodic overprotection is not used as an input for determining piping inspection locations. Cathodic protection efficacy is currently referenced as an input; however, the staff seeks clarification with respect to whether this considers areas that have been overprotected.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 3 Page 2 of 4 Request:

State the basis for why cathodic overprotection is not used as an input for determining piping inspection locations. Alternatively, revise the SLRA (as appropriate) to consider cathodic overprotection as an input for determining piping inspection locations.

Response to RAI B.2.3.27-2:

Commitment 30q, as added in Enclosure 06a of Reference 1, establishes that, The cathodic protection system for buried piping shall also include a limiting critical potential of -1,200 mV to prevent overprotection. Additionally, commitment 30g and associated enhancement in SLRA Section B.2.3.27 are revised to include cathodic overprotection as an input for determining inspection locations. Previous changes from Enclosure 06a of Reference 1 are shown in bold, black font.

References:

1. L-MT-23-025, Monticello Nuclear Generating Plant, Docket No. 50-263, Renewed Facility Operating License No. DPR-22, Subsequent License Renewal Application Supplement 2, ML23177A218.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 3 Page 3 of 4 Associated SLRA Revisions:

SLRA Table A-3, Commitment 30g on page A-82 is revised as follows:

No. Aging NUREG2191 Commitment Implementation Management Section Schedule Program or Activity (Section) 30 Buried and XI.M41 g) Include the guidance for piping No later than 6 Underground inspection location selection as months prior to Piping and follows: (a) risk ranking system the SPEO, or no Tanks software incorporates inputs that later than the last (A.2.2.27) include coating type, coating refueling outage condition, cathodic protection prior to the SPEO efficacy, cathodic protection overprotection history, backfill Implement the characteristics, soil resistivity, pipe AMP and start contents, and pipe function; (b) 10-year interval opportunistic examinations of inspections no nonleaking pipes may be credited earlier than 10 toward examinations if the location years prior to the selection criteria are met; and (c) the SPEO.

use of guided wave ultrasonic examinations may not be substituted Commitment for the required inspections. 30q will be implemented 5 years prior to the SPEO in order to credit the system for pre-SPEO inspections.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 3 Page 4 of 4 SLRA Section B.2.3.27 on page B-200 is revised as follows:

Element Affected Enhancement

4. Detection of Aging Effects Update MNGP BUPT AMP procedures as appropriate:

• Clarify the guidance for piping inspection location selection as follows: (a) a risk ranking system software incorporates inputs that include coating type, coating condition, cathodic protection efficacy, cathodic protection overprotection history, backfill characteristics, soil resistivity, pipe contents, and pipe function; (b) opportunistic examinations of nonleaking pipes may be credited toward examinations if the location selection criteria are met; and (c) the use of guided wave ultrasonic exam may not be substituted for the required inspections.

4 RAI B.2.3.15-1

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 4 Page 1 of 5 RAI B.2.3.15-1 Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 CFR) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the U.S.

Nuclear Regulatory Commission (NRC) staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described in the requests for information.

Background:

The Monitoring and Trending program element in Aging Management Program (AMP)

XI.M26, Fire Protection, in Volume 2 of NUREG-2191, Generic Aging Lessons learned for Subsequent License Renewal (GALL-SLR) Report (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17187A031), states the following:

• The results of inspections of the aging effects of cracking and loss of material on fire barrier penetration seals, fire barriers, fire damper assemblies, and fire doors are trended to provide for timely detection of aging effects so that the appropriate corrective actions can be taken.

• The performance of the halon/CO2 fire suppression system is monitored during the periodic test to detect any degradation in the system. These periodic tests provide data necessary for trending.

The Detection of Aging Effects program element in GALL-SLR Report AMP XI.M26 states, Visual inspections of the halon/CO2 or clean agent fire suppression system are performed to detect any sign of corrosion before the loss of the component intended function. The Acceptance Criteria program element in GALL-SLR Report AMP XI.M26 states, Also, inspection results for the halon/CO2 or clean agent fire suppression system are acceptable if there are no indications of excessive loss of material. While GALL-SLR does not explicitly state that the halon fire suppression system inspection results be trended, the NRC staff notes that the expectation would be that the results be trended since there could be loss of material that is not considered excessive and determined not to result in a loss of intended function. This information would be trended to monitor how the condition of the halon fire suppression system is changing over time in order to take timely corrective action.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 4 Page 2 of 5 Issue:

The enhancement to the Monitoring and Trending program element in Subsequent License Renewal Application (SLRA) Section B.2.3.15 states, Trend the inspection results for timely detection of aging effect so that appropriate corrective actions can be taken. However, SLRA Table A-3 states, Trend the inspection results on fire barrier penetration seals, fire barriers, fire damper assemblies, and fire doors for timely detection of aging effect so that appropriate corrective actions can be taken. SLRA Section B.2.3.15 appears to include trending of all Fire Protection program inspection results, while SLRA Table A-3 appears to exclude the halon fire suppression system.

Section 3.3 of Report No. XCELMO00017-REPT-065, Subsequent License Renewal Aging Management Program Basis Document - Fire Protection (basis document), states that Section 4.5 of the basis document documents that the Cable Spreading Room Halon fire suppression system procedures specify trending of inspection results of this system.

However, the NRC staff did not identify where this documentation is made in Section 4.5, and did not identify documentation related to trending periodic test results. The staff does note that it states, The MNGP Cable Spreading Room halon fire suppression system is monitored during the periodic tests to detect any degradation in the system. In addition, the staff did not identify where Revision 28 of Procedure 0328, Cable Spreading Room Halon System, discusses trending of inspection or periodic test results.

Table 1 in Section 7.0 of the basis document states that Procedure 0328 will be updated to trend inspection results and where practical, project degradation until the next scheduled inspection. However, it does not state it will be updated to include trending of periodic test results.

During the audit of the Fire Protection program, the applicant stated that the halon fire suppression system in the Cable Spreading Room does not require enhancement for trending because trending of the periodic tests are already performed under FP-E-MR-03, Maintenance Rule Monitoring. However, FP-E-MR-03 does not discuss trending the periodic tests of the halon fire suppression system, and does not reference Procedure 0328 or the basis document. In addition, Procedure 0328 and the basis documents do not reference FP-E-MR-03.

Therefore, it is unclear to the NRC staff how trending of the halon fire suppression system inspection and periodic test results are performed, and will continue to be performed during the subsequent period of extended operation (SPEO), given the lack of clear documentation in plant-specific procedures and documents.

Request:

Consistent with the Detection of Aging Effects and Monitoring and Trending program elements in GALL-SLR Report AMP XI.M26, please provide sufficient information demonstrating that trending of the halon fire suppression system inspection and periodic test results will be performed during the SPEO, including where the requirements are documented in plant-specific procedures. Alternatively, revise enhancement 18.b) in SLRA Table A-3 to include trending the halon fire suppression system inspection and periodic test

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 4 Page 3 of 5 results, and, for consistency, the corresponding enhancement to the Monitoring and Trending program element in SLRA Section B.2.3.15.

Response to RAI B.2.3.15-1:

The cable spreading room halon system is subject to both inspection and functional testing as a form of monitoring and trending the system performance.

SLRA Table A-3, Commitment 18.b) will be updated to include trending of inspection and periodic test results and include the halon suppression system as part of the fire protection system commodities that are monitored and trended.

SLRA Section B.2.3.15 includes the halon suppression system as part of the fire protection system commodities that are monitored and trended. This section also contains an enhancement to Trend the inspection results for timely detection of aging effect so that appropriate corrective actions can be taken. For clarity, this statement will be modified to include trending of periodic test results.

References:

None Associated SLRA Revisions:

Associated SLRA changes are provided below.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 Enclosure 04 Page 4 of 5 SLRA Appendix A, Table A-3, Commitment 18.b) on page A-64, is modified as follows:

No. Aging Management NUREG-2191 Commitment Implementation Schedule Program or Activity Section (Section) 18 Fire Protection XI.M26 The Fire Protection AMP is an existing program that will be enhanced to: No later than 6 months prior to (A.2.2.15) the SPEO, or no later than the a) Update the fire damper assemblies inspection procedure(s) to last refueling outage prior to the inspect for corrosion and cracking on all in-scope fire damper SPEO assemblies. Include no signs of corrosion, cracking or degradation that could result in loss of fire protection capability due to loss of material as acceptance criteria for fire damper assemblies.

b) Trend the inspection results on fire barrier penetration seals, fire barriers, fire damper assemblies, halon suppression system, and fire doors for timely detection of aging effects so that appropriate corrective actions can be taken. Trend the periodic test results of the halon suppression system for timely detection of aging effects so that appropriate corrective action can be taken. Where practical, identified degradation is projected until the next scheduled inspection.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 4 Page 5 of 5 SLRA Appendix B, Section B.2.3.15 page B-109, is modified as follows:

Element Affected Enhancement

5. Monitoring and Trending Trend the inspection and periodic test results for timely detection of aging effects so that appropriate corrective actions can be taken. Where practical, identified degradation is projected until the next scheduled inspection.

5 RAI B.2.3.15-2

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 5 Page 1 of 4 RAI B.2.3.15-2 Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 CFR) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the U.S.

Nuclear Regulatory Commission (NRC) staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described in the requests for information.

Background:

The Acceptance Criteria program element in GALL-SLR Report AMP XI.M26 states, no significant indications of cracking and loss of material of fire barrier walls, ceilings, and floors and in other fire barrier materials.

Figure 5.3 in Revision 23 of 4 AWI-08.01.00, Fire Protection Program Plan, and Revision 50 of Procedure 0275-02, Fire Barrier Wall, Damper and Floor Inspection, state to consider cracks greater than 0.25 inches wide in walls, floors, and ceilings. However, these documents did not cite a reference for the basis for this crack width limit.

During the audit of the Fire Protection program, the applicant stated that the basis for the crack width limit is in Section 3.2.18.2 of MPS-0924, Installation of Electrical and Mechanical Penetration Seals. The applicant further stated that the 0.25 inch crack width can be extrapolated to cracks in fire barriers because Section 3.2.18 of MPS-0924 states the specification is for sealing openings in hollow walls, with or with out a penetrant or existing sealant material.

Issue:

Section 3.2.18 of MPS-0924 provides instructions (Sections 3.2.18.1, 3.2.18.2, and 3.2.18.3) for installing hollow wall fire stop seals for sealing of openings in hollow-walls with gypsum wallboard surface, either single or double layer, with or without penetrant, and with or without existing sealant materials. Section 3.2.18.2 of MPS-0924 provides instructions for applying thermal board or gypsum wallboard patches. It states, Patch may be in sections, end should be cut to clear penetrant with no more than 1/4 [inch] gap width. Section 3.2.18.3 of MPS-0924 includes instructions for applying a thermal mastic to joints between mating surfaces, edges of patch, cracks between patch sections, and between patch penetrant. Therefore, it appears that the 0.25 inch gap width in Section 3.2.18.2 would be

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 5 Page 2 of 4 covered by thermal mastic and not left uncovered.

It is unclear to the NRC staff how a 0.25 inch wide gap between the patch and penetrant that will eventually be covered by thermal mastic can be extrapolated to cracks in other fire barriers.

Request:

Please provide sufficient information, including references, to support extrapolating the 0.25 inch wide gap in MPS-0924 to other fire barriers.

Response to RAI B.2.3.15-2:

The fire protection procedures associated with fire barrier inspections require revision. The procedures will be revised to remove the 0.25 inch wide crack from the list of criteria to consider for fire barrier inspections with the exception of thermal mastic materials used in fire barrier penetration seals as allowed by design.

SLRA Table A-3, Commitment 18e will be updated to include a commitment to remove the 0.25 inch wide crack from the criteria to consider for fire barrier inspections with the exception of thermal mastic materials used in fire barrier penetration seals as allowed by design.

SLRA Section B.2.3.15 includes an enhancement related to acceptance criteria. This will be updated to include an enhancement to remove the 0.25 inch wide crack from the criteria to consider for fire barrier inspections with the exception of thermal mastic materials used in fire barrier penetration seals as allowed by design.

References:

None Associated SLRA Revisions:

Associated SLRA changes are provided below.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 5 Page 3 of 4 SLRA Appendix A, Table A-3, Commitment 18e on page A-65, is modified as follows:

No. Aging Management NUREG-2191 Commitment Implementation Schedule Program or Activity Section (Section) 18 Fire Protection XI.M26 The Fire Protection AMP is an existing program that will be enhanced to: No later than 6 months prior to (A.2.2.15) the SPEO, or no later than the e) Update Fire Protection AMP documents to include "no separation last refueling outage prior to the of layers of material" and "no ruptures or punctures" as SPEO acceptance criteria for fire barrier penetration seals. Remove Cracks greater than 0.25 inches wide, from the list of criteria to consider during fire barrier inspections with the exception of thermal mastic materials used in fire barrier penetration seals as allowed by design.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 5 Page 4 of 4 SLRA Section B.2.3.15 on page B-109 is modified as follows:

Element Affected Enhancement

6. Acceptance Criteria Update document to include no signs of corrosion, cracking or degradation that could result in loss of fire protection capability due to loss of material as acceptance criteria for fire damper assemblies.

Update Fire Protection AMP documents to include "no separation of layers of material" and "no ruptures or punctures" as acceptance criteria for fire barrier penetration seals. Remove Cracks greater than 0.25 inches wide, from the list of criteria to consider during fire barrier inspections with the exception of thermal mastic materials used in fire barrier penetration seals as allowed by design.

6 RAI 4.3.2-2

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 6 Page 1 of 3 RAI 4.3.2-2 Regulatory Basis:

Pursuant to 10 CFR 54.21(c), the SLRA must include an evaluation of time-limited aging analyses (TLAAs). The applicant must demonstrate that (i) the analyses remain valid for the period of extended operation, (ii) the analyses have been projected to the end of the period of extended operation, or (iii) the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

Background:

In Enclosure 10a of its supplement dated July 18, 2023 (ADAMS Accession No. ML23199A154), the applicant explained that there is no fatigue waiver evaluation done for the instrumentation nozzles and jet pump instrumentation nozzles in accordance with the ASME Code Section III, Paragraph N-415.1 or NB-3222.4(d) provisions for fatigue waiver.

Issue:

Given the lack of fatigue waiver evaluation in accordance with ASME Code Section III Paragraph N-415.1 or NB-3222.4(d), the staff needs additional information on how the applicant ensures that the cumulative usage factor (CUF) values for these nozzles do not exceed the fatigue design limit (1.0).

Request:

1. Clarify whether the stresses applied to the instrumentation nozzles and jet pump instrumentation nozzles are less than the fatigue endurance limit. If not, discuss the following: (1) whether the other reactor pressure vessel nozzles or components evaluated in SLRA Section 4.3.3 are bounding for the instrumentation nozzles and jet pump instrumentation nozzles in terms of the applied transient stresses and resultant CUF; and (2) the basis of determining that the other nozzles or components are bounding for the instrumentation nozzles and jet pump instrumentation nozzles.

2. If the Fatigue Monitoring aging management program will be used to manage the aging effect of cumulative fatigue damage for the instrumentation nozzles and jet pump instrumentation nozzles, describe how the program will be used to manage the aging effect for these nozzles.

RAI 4.3.2-2 Response:

1. The stresses applied to the instrumentation nozzles and jet pump instrumentation nozzles are conservatively assumed to be greater than the fatigue endurance limit for those components.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 6 Page 2 of 3 (1) The other reactor pressure vessel nozzles are bounding for the instrumentation nozzles and jet pump instrumentation nozzles in terms of applied transient stresses and resultant CUF.

(2) The basis of determining that the other nozzles or components are bounding for the instrumentation nozzles and jet pump instrumentation nozzles is as follows:

The original RPV stress report used a qualitative approach to show that thermal transients would not result in stresses that exceed allowable values for these components. The statements for these nozzles were reviewed and found to remain valid for the 80-year plant life. No formal fatigue waivers were done for these nozzles.

The conclusion from the original RPV stress report for the jet pump instrumentation nozzle is provided as follows:

"Attachment "D" of the specification specifies a change in temperature from the isothermal temperature of 546°F to 370°F at a rate of 1000°F/hr. This rate of change is exactly the same as that acting on the steam outlet nozzle and analyzed for. There is, however, no fluid flow through the jet pump instrument nozzle making this a less severe transient than that acting on the steam outlet nozzle.

The jet pump instrument nozzle has an inside diameter of 4" compared to 18" for the steam outlet, making the nozzle to shell junction less critical. It can, therefore, be concluded that provisions for primary plus secondary stresses have been satisfied."

The steam outlet nozzle (referenced above) has a fatigue usage for 80 years of 0.1872 as presented in SLRA Table 4.3.3-1. CUF is less than 1.0 and is therefore acceptable.

When compared to the steam outlet nozzle, the jet pump instrumentation nozzle has the same rate of temperature change, is smaller in diameter, and has no fluid flow through the nozzle. As a result, the jet pump instrumentation nozzles can be considered bounded by the more severe transient stresses affecting the steam outlet nozzle. Based on that, it is reasonable to conclude that the jet pump instrumentation nozzle would have a fatigue usage of less than 0.1872. This CUF less than 1.0 is therefore considered acceptable.

The conclusion from the original RPV stress report for the instrumentation nozzles is provided as follows:

No specific transient has been specified for the instrumentation nozzles. They are, therefore, under the action of normal operating transients and rapid cool down. These transients have been analyzed for in other areas of the vessel and on nozzles with larger openings. By comparison with other nozzles having more severe shocks due to direct flows, it can be concluded that provisions for primary plus secondary stresses have been met here.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 6 Page 3 of 3 The nozzle location with the highest projected fatigue usage for 80 years is 0.4490 as presented in SLRA Table 4.3.3-1. CUF is less than 1.0 and is therefore acceptable.

When compared to the other nozzles, the instrumentation nozzles have the same transients contribute to CUF at these locations. As a result, the analysis for the other nozzles can be considered bounding and used to predict a usage factor. It is therefore reasonable to conclude that the instrumentation nozzles would have a fatigue usage equivalent or less than the highest nozzle value of 0.4490. This is a CUF less than 1.0 and therefore considered acceptable.

In conclusion, the nozzles addressed in SLRA Section 4.3.3 are bounding for the jet pump instrumentation nozzles and instrumentation nozzles.

2. The ASME Code,Section III, Class 1 component fatigue waivers will be managed by the Fatigue Monitoring AMP (B.2.2.1) through the SPEO. The Fatigue Monitoring AMP (B.2.2.1) verifies the continued acceptability of existing analyses through manual cycle counting for monitoring CUFs for the selected component locations using cycle-based fatigue monitoring. For the instrumentation nozzles and jet pump instrumentation nozzles, since these components are bounded by other locations, no additional transients are required to be monitored in order to adequately manage fatigue.

References:

None Associated SLRA Revisions:

No SLRA changes have been identified as a result of this response.

Document Control Desk L-MT-23-036 Page 1 Attachment 2 Enclosures Index Enclosure Subject No.

Addition of (a)(2) Function to Drywell Atmosphere Cooling System and 01 Components

Enclosure 01 Addition of (a)(2) Function to Drywell Atmosphere Cooling System and Components

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 1 of 19 Addition of (a)(2) Function to Drywell Atmosphere Cooling System and Components Add the appropriate (a)(2) functional requirements to the drywell coolers and other Drywell Atmosphere Cooling System components.

Affected SLRA Sections: Table 1.7-1, 2.1.4.2.1, Table 2.2-1, 2.3.3.11, Table 2.3.3-11, 2.3.3.14, Table 2.3.3-14, 3.3.2.1.11, 3.3.2.1.14, Table 3.3.2-11, Table 3.3.2-14 SLRA Page Numbers: 1-17, 2.1-16, 2.2-2, 2.3-49, 2.3-50, 2.3-51, 2.3-57, 2.3-58, 3.3-13, 3.3-16, 3.3-213, 3.3-218, 3.3-219, 3.3-234, 3.3-267 to 3.3-273 Description of Change:

The Drywell Coolers and their Reactor Building Closed Cooling Water (RBC) supply as well as other components in the Drywell Atmosphere Cooling (DAC) system have NSR components that are required to maintain the bioshield concrete temperature below 150 F and local temperatures below 200 F. Maintaining these temperatures ensure the integrity of the biological shield wall to maintain its SR function. The SLRA is updated to include the systems and components with the appropriate non-safety affecting safety-related intended functions.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 2 of 19 SLRA Table 1.7-1 on page 1-17 is revised as follows:

Table 1.7-1 Acronyms Acronym Description CWT Circulating Water DAC Drywell Atmosphere Cooling DBA Design Basis Accident SLRA Section 2.1.4.2.1 on page 2.1-16 is revised as follows:

CST Tanks: The MNGP CST tanks are NSR components. These tanks provide the normal suction source to the High Pressure Coolant Injection System (HPCI). They also are the credited source of water during an SBO event (USAR Section 8.12). Therefore, they are inscope for SLR.

DAC System and Associated RBC System Components: The systems remove heat from the drywell, which is required to maintain the bioshield concrete temperatures below 150°F and local temperatures below 200°F. Maintaining these temperatures ensures the integrity of the biological shield wall.

SLRA Table 2.2-1 on page 2.2-2 is revised as follows:

Table 2.2-1 Plant Level Scoping Report Results In-scope SLRA System Name Initial LRA System Name Section for SLR Drywell Atmosphere Cooling (DAC) NY N/A2.3.3.11 Heating and Ventilation Heating and Ventilation (HTV) Y 2.3.3.11 Heating Boiler (HTB) N N/A

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 3 of 19 SLRA Section 2.3.3.11 on page 2.3-49 is revised as follows:

secondary containment isolation conditions are included with the SCT System (Section 2.3.2.6).

General plant heating is provided by a piping network originating at the plant heating boiler and extending throughout most of the plant to supply heated water and/or steam to various unit heaters. Three notable locations not directly served are the drywell, Off-Gas Storage Building, and portions of the plant serviced by the EFT System.

The DAC System is included as part of the HTV System for SLR purposes. The primary containment cooling and ventilation system consists of four air coolers, ductwork, fans, and controls which maintain the drywell atmosphere below a 135°F bulk average temperature. The DAC System distributes cooled gas via a ring supply header in the drywell. This header distributes cooling gas to all areas of the drywell, including special duct runs to ventilation fan motors, the reactor head areas, the recirculation pump motors, and the annular space between the reactor pressure vessel and the biological shield.

Boundary The HTV System boundaries are reflected on the following SLRBDs:

SLR-36033 SLR-36041 SLR-36259 SLR-36259-1 SLR-36259-2 SLR-36260 SLR-36261 SLR-36262 SLR-36263 SLR-36266 SLR-36267-3 SLR-36267 SLR-36348 SLR-36664 SLR-36776 SLR-36807 SLR-36808 SLR-36881 SLR-46162 SLR-51142-1 SLR-67588

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 4 of 19 System Intended Functions SR functions (10 CFR 54.4(a)(1)):

(1) The HTV System shall remove heat produced by equipment, piping, and motors for the RHR, CSP, HPCI, and DGN Systems during design basis events.

(2) Provide for controlled flow direction and release of radioactive gases during non-accident conditions.

NSR components that could affect SR functions (10 CFR 54.4(a)(2)):

(1) Maintain integrity of NSR components such that no interaction with SR components could prevent satisfactory accomplishment of a safety function.

(2) The DAC System includes NSR SSCs necessary to complete the flowpath of cooling air through the drywell to limit temperatures as needed to support the biological shield walls structural integrity.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 5 of 19 SLRA Section 2.3.3.11 on page 2.3-50 is revised as follows:

FP, EQ, PTS, ATWS, and SBO functions (10 CFR 54.4(a)(3)):

(1) Perform a function that demonstrates compliance with the Commissions regulations for FP and EQ.

USAR References Sections 5.2.1.2.1, 5.2.2.5.2, 5.3.4, 10.3.1, and 10.3.2 Components Subject to AMR Table 2.3.3-11 lists the HTV System component types that require an AMR and their associated component intended functions.

Table 3.3.2-11 provides the results of the AMR.

SLRA Table 2.3.3-11 on pages 2.3-50 and 2.3-51 is revised to add component types as follows:

Table 2.3.3-11 Heating and Ventilation System Components Subject to Aging Management Review Component Type Component Intended Function(s)

Blower Housing (Drywell Atmosphere Cooling Pressure Boundary Units)

Flexible Connection Pressure Boundary Moisture Eliminator Housing Pressure Boundary

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 6 of 19 SLRA Section 2.3.3.14 on page 2.3-57 is revised as follows:

NSR components that could affect SR functions (10 CFR 54.4(a)(2)):

(1) Maintain integrity of NSR components such that no interaction with SR components could prevent satisfactory accomplishment of a safety function.

(2) Remove heat transferred to the DAC System to limit drywell temperatures as needed to support the biological shield walls structural integrity.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 7 of 19 SLRA Table 2.3.3-14 on pages 2.3-57 and 2.3-58 is revised as follows:

Table 2.3.314 Reactor Building Closed Cooling Water System Components Subject to Aging Management Review Bolting (Closure) Mechanical Closure Heat Exchanger (Drywell Coolers) Tubes Heat Transfer Leakage Pressure Boundary Heat Exchanger (RB Cooling Water) Shell Leakage Pressure Boundary Side Components Heat Exchanger (RB Cooling Water) Heat Transfer Tubes Pressure Boundary Heat Exchanger (RB Cooling Water) Tube Leakage Pressure Boundary Side Components Hoses Leakage Pressure Boundary Insulated Piping, Piping Components Leakage Pressure Boundary Insulated Valve Body Leakage Pressure Boundary Piping Elements Leakage Pressure Boundary Piping, Piping Components Leakage Boundary Pressure Boundary Pump Casing (Reactor Building Cooling Leakage Pressure Boundary Water Pumps)

Tanks (Chemical Feeder) Leakage Pressure Boundary Tanks (Reactor Building Cooling Water Leakage Pressure Boundary Surge Tank)

Valve Body Leakage Boundary Pressure Boundary

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 8 of 19 SLRA Section 3.3.2.1.11 on page 3.3-13 is revised as follows:

3.3.2.1.11 Heating and Ventilation Materials The materials of construction for the HTV System components are:

Carbon and Low Alloy Steel Bolting Carbon Steel Copper Alloy with 15% Zinc or Less Copper Alloy with Greater Than 15% Zinc Elastomer Galvanized Steel Glass Gray Cast Iron Stainless Steel Stainless Steel Bolting Environments The HTV System components are exposed to the following environments:

Air - Indoor Uncontrolled Closed-Cycle Cooling Water Condensation Gas Raw Water Treated Water Treated Water >140 F Aging Effects Requiring Management The following aging effects associated with the HTV System require management:

Cracking Flow Blockage Hardening or Loss of Strength Long-Term Loss of Material Loss of Material Loss of Preload Reduction of Heat Transfer

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 9 of 19 SLRA Section 3.3.2.1.14 on page 3.3-16 is revised as follows:

3.3.2.1.14 Reactor Building Closed Cooling Water Aging Effects Requiring Management The following aging effects associated with the RBC System require management:

Cracking Flow Blockage Long-Term Loss of Material Loss of Coating or Lining Integrity Loss of Material Loss of Preload Reduction of Heat Transfer

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 10 of 19 SLRA Table 3.3.2-11 on pages 3.3-213, 3.3-218, 3.3-219, and 3.3-234 is revised as follows:

Table 3.3.2-11 Heating and Ventilation - Summary of Aging Management Evaluation Aging Effect Aging Component Intended NUREG-219 Table 1 Material Environment Requiring Management Notes Type Function 1 Item Item Management Program Blower Housing Pressure Carbon Air Indoor Loss of External Surfaces VII.I.A-77 3.3.1-078 A (Drywell Boundary Steel Uncontrolled Material Monitoring of Atmosphere (External) Mechanical Cooling Units) Components (B.2.3.23)

Blower Housing Pressure Carbon Air Indoor Loss of Inspection of V.B.E-25 3.2.1-044 A (Drywell Boundary Steel Uncontrolled Material Internal Surfaces in Atmosphere (Internal) Miscellaneous Cooling Units) Piping and Ducting Components (B.2.3.24)

Ducting and Pressure Galvanized Air Indoor None None VII.J.AP-13 3.3.1-116 C Components Boundary Steel Uncontrolled (External)

Ducting and Pressure Galvanized Air Indoor None None VII.J.AP-13 3.3.1-116 C Components Boundary Steel Uncontrolled (Internal)

Flexible Pressure Elastomer Air Indoor Hardening or External Surfaces VII.I.AP-102 3.3.1-076 A Connection Boundary Uncontrolled Loss of Monitoring of (External) Strength Mechanical Components (B.2.3.23)

Flexible Pressure Elastomer Air Indoor Loss of External Surfaces VII.I.AP-113 3.3.1-082 A Connection Boundary Uncontrolled Material Monitoring of (External) Mechanical Components (B.2.3.23)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 11 of 19 Table 3.3.2-11 Heating and Ventilation - Summary of Aging Management Evaluation Aging Effect Aging Component Intended NUREG-219 Table 1 Material Environment Requiring Management Notes Type Function 1 Item Item Management Program Flexible Pressure Elastomer Air Indoor Hardening or Inspection of VII.F3.A-504 3.3.1-085 A Connection Boundary Uncontrolled Loss of Internal Surfaces (Internal) Strength in Miscellaneous Piping and Ducting Components (B.2.3.24)

Flexible Pressure Elastomer Air Indoor Loss of Inspection of VII.F3.AP-103 3.3.1-096 A Connection Boundary Uncontrolled Material Internal Surfaces (Internal) in Miscellaneous Piping and Ducting Components (B.2.3.24)

Moisture Pressure Galvanized Air Indoor None None VII.J.AP-13 3.3.1-116 C Eliminator Boundary Steel Uncontrolled Housing (External)

Moisture Pressure Galvanized Air Indoor None None VII.J.AP-13 3.3.1-116 C Eliminator Boundary Steel Uncontrolled Housing (Internal)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 12 of 19 SLRA Table 3.3.2-14 on pages 3.3-267 to 3.3-273 is revised as follows:

Table 3.3.2-14 Reactor Building Closed Cooling Water - Summary of Aging Management Evaluation Aging Effect Component Intended Aging Management NUREG-2191 Table 1 Material Environment Requiring Notes Type Function Program Item Item Management Bolting (Closure) Mechanical Carbon and Air Indoor Loss of Material Bolting Integrity VII.I.A03 3.3.1012 A Closure Low Alloy Uncontrolled (B.2.3.10)

Steel Bolting (External)

Bolting (Closure) Mechanical Carbon and Air Indoor Loss of Preload Bolting Integrity VII.I.AP124 3.3.1015 A Closure Low Alloy Uncontrolled (B.2.3.10)

Steel Bolting (External)

Bolting (Closure) Mechanical Stainless Air Indoor Cracking Bolting Integrity VII.I.A426 3.3.1145 A Closure Steel Bolting Uncontrolled (B.2.3.10)

(External)

Bolting (Closure) Mechanical Stainless Air Indoor Loss of Material Bolting Integrity VII.I.A03 3.3.1012 A Closure Steel Bolting Uncontrolled (B.2.3.10)

(External)

Bolting (Closure) Mechanical Stainless Air Indoor Loss of Preload Bolting Integrity VII.I.AP124 3.3.1015 A Closure Steel Bolting Uncontrolled (B.2.3.10)

(External)

Heat Exchanger Heat Copper Air Indoor Reduction of Inspection of Internal VII.F3.A-419 3.3.1096a A (Drywell Coolers) Transfer Alloy with Uncontrolled Heat Transfer Surfaces in Tubes 15% Zinc or (External) Miscellaneous Piping Less and Ducting Components (B.2.3.24)

Heat Exchanger Heat Copper Closed Cycle Reduction of Closed Treated Water VII.C2.AP205 3.3.1050 A (Drywell Coolers) Transfer Alloy with Cooling Water Heat Transfer Systems (B.2.3.12)

Tubes 15% Zinc or (Internal)

Less Heat Exchanger Leakage Copper Alloy Air Indoor None None VII.J.AP-144 3.3.1114 C (Drywell Coolers) Pressure with 15% Uncontrolled Tubes Boundary Zinc or Less (External)

Heat Exchanger Leakage Copper Alloy Closed Cycle Loss of Material Closed Treated Water VII.C2.AP199 3.3.1046 C

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 13 of 19 Table 3.3.2-14 Reactor Building Closed Cooling Water - Summary of Aging Management Evaluation Aging Effect Component Intended Aging Management NUREG-2191 Table 1 Material Environment Requiring Notes Type Function Program Item Item Management (Drywell Coolers) Pressure with 15% Cooling Water Systems (B.2.3.12)

Tubes Boundary Zinc or Less (Internal)

Heat Exchanger - Leakage Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A-77 3.3.1-078 A (RB Cooling Pressure Uncontrolled Monitoring of Water) Shell Side Boundary (External) Mechanical Components Components (B.2.3.23)

Heat Exchanger - Leakage Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP189 3.3.1046 A (RB Cooling Pressure Cooling Water Systems (B.2.3.12)

Water) Shell Side Boundary (Internal)

Components Heat Exchanger - Heat Stainless Closed Cycle Reduction of Closed Treated Water VII.C2.AP-188 3.3.1-050 A (RB Cooling Transfer Steel Cooling Water Heat Transfer Systems (B.2.3.12)

Water) Tubes (External)

Heat Exchanger - Heat Stainless Raw Water Reduction of Inspection of Internal VIII.E.S-437 3.4.1-090 A (RB Cooling Transfer Steel (Internal) Heat Transfer Surfaces in Water) Tubes Miscellaneous Piping and Ducting Components (B.2.3.24)

Heat Exchanger - Pressure Stainless Closed Cycle Loss of Material Closed Treated Water VII.C2.A-52 3.3.1-049 C (RB Cooling Boundary Steel Cooling Water Systems (B.2.3.12)

Water) Tubes (External)

Heat Exchanger - Pressure Stainless Raw Water Flow Blockage Inspection of Internal VII.C1.A-727 3.3.1-134 A (RB Cooling Boundary Steel (Internal) Surfaces in Water) Tubes Miscellaneous Piping and Ducting Components (B.2.3.24)

Heat Exchanger - Pressure Stainless Raw Water Loss of Material Inspection of Internal VII.C1.A-727 3.3.1-134 A (RB Cooling Boundary Steel (Internal) Surfaces in Water) Tubes Miscellaneous Piping and Ducting

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 14 of 19 Table 3.3.2-14 Reactor Building Closed Cooling Water - Summary of Aging Management Evaluation Aging Effect Component Intended Aging Management NUREG-2191 Table 1 Material Environment Requiring Notes Type Function Program Item Item Management Components (B.2.3.24)

Heat Exchanger Leakage Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A77 3.3.1078 A (RB Cooling Pressure (with Internal Uncontrolled Monitoring of Water) Tube Side Boundary Coating) (External) Mechanical Components Components (B.2.3.23)

Heat Exchanger Leakage Carbon Steel Raw Water LongTerm Loss OneTime Inspection VII.C1.A532 3.3.1193 A (RB Cooling Pressure (with Internal (Internal) of Material (B.2.3.20)

Water) Tube Side Boundary Coating)

Components Heat Exchanger Leakage Carbon Steel Raw Water Loss of Coating Internal VII.C1.A416 3.3.1138 A (RB Cooling Pressure (with Internal (Internal) or Lining Integrity Coatings/Linings for Water) Tube Side Boundary Coating) InScope Piping, Piping Components Components, Heat Exchangers, and Tanks (B.2.3.28)

Heat Exchanger Leakage Carbon Steel Raw Water Loss of Material Inspection of Internal VII.C1.A414 3.3.1139 E, 1 (RB Cooling Pressure (with Internal (Internal) Surfaces in Water) Tube Side Boundary Coating) Miscellaneous Piping Components and Ducting Components (B.2.3.24)

Hoses Leakage Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A77 3.3.1078 A Pressure Uncontrolled Monitoring of Boundary (External) Mechanical Components (B.2.3.23)

Hoses Leakage Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A Pressure Cooling Water Systems (B.2.3.12)

Boundary (Internal)

Insulated Piping, Leakage Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A Piping Pressure Cooling Water Systems (B.2.3.12)

Components Boundary (Internal)

Insulated Piping, Leakage Carbon Steel Condensation Loss of Material External Surfaces VII.I.A405a 3.3.1132 A

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 15 of 19 Table 3.3.2-14 Reactor Building Closed Cooling Water - Summary of Aging Management Evaluation Aging Effect Component Intended Aging Management NUREG-2191 Table 1 Material Environment Requiring Notes Type Function Program Item Item Management Piping Pressure (External) Monitoring of Components Boundary Mechanical Components (B.2.3.23)

Insulated Valve Leakage Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A Body Pressure Cooling Water Systems (B.2.3.12)

Boundary (Internal)

Insulated Valve Leakage Carbon Steel Condensation Loss of Material External Surfaces VII.I.A405a 3.3.1132 A Body Pressure (External) Monitoring of Boundary Mechanical Components (B.2.3.23)

Piping Elements Leakage Glass Air Indoor None None VII.J.AP48 3.3.1117 A Pressure Uncontrolled Boundary (External)

Piping Elements Leakage Glass Closed Cycle None None VII.J.AP166 3.3.1117 A Pressure Cooling Water Boundary (Internal)

Piping, Piping Leakage Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A77 3.3.1078 A Components Pressure Uncontrolled Monitoring of Boundary (External) Mechanical Components (B.2.3.23)

Piping, Piping Leakage Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A Components Boundary Cooling Water Systems (B.2.3.12)

(Internal)

Piping, Piping Leakage Copper Alloy Air Indoor None None VII.J.AP144 3.3.1114 A Components Pressure with 15% Uncontrolled Boundary Zinc or Less (External)

Piping, Piping Leakage Copper Alloy Closed Cycle Loss of Material Closed Treated Water VII.C2.AP199 3.3.1046 A Components Pressure with 15% Cooling Water Systems (B.2.3.12)

Boundary Zinc or Less (Internal)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 16 of 19 Table 3.3.2-14 Reactor Building Closed Cooling Water - Summary of Aging Management Evaluation Aging Effect Component Intended Aging Management NUREG-2191 Table 1 Material Environment Requiring Notes Type Function Program Item Item Management Piping, Piping Leakage Copper Alloy Air Indoor Cracking External Surfaces VIII.H.S454 3.4.1106 A Components Pressure with Greater Uncontrolled Monitoring of Boundary Than 15% (External) Mechanical Zinc Components (B.2.3.23)

Piping, Piping Leakage Copper Alloy Closed Cycle Loss of Material Closed Treated Water VII.C2.AP199 3.3.1046 A Components Pressure with Greater Cooling Water Systems (B.2.3.12)

Boundary Than 15% (Internal)

Zinc Piping, Piping Leakage Copper Alloy Closed Cycle Loss of Material Selective Leaching VII.C2.AP43 3.3.1072 A Components Pressure with Greater Cooling Water (B.2.3.21)

Boundary Than 15% (Internal)

Zinc Piping, Piping Leakage Stainless Air Indoor Cracking OneTime Inspection VII.C2.AP209a 3.3.1004 A Components Pressure Steel Uncontrolled (B.2.3.20)

Boundary (External)

Piping, Piping Leakage Stainless Air Indoor Loss of Material OneTime Inspection VII.C2.AP221a 3.3.1006 A Components Pressure Steel Uncontrolled (B.2.3.20)

Boundary (External)

Piping, Piping Leakage Stainless Closed Cycle Loss of Material Closed Treated Water VII.C2.A52 3.3.1049 A Components Pressure Steel Cooling Water Systems (B.2.3.12)

Boundary (Internal)

Piping, Piping Pressure Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A77 3.3.1078 A Components Boundary Uncontrolled Monitoring of (External) Mechanical Components (B.2.3.23)

Piping, Piping Pressure Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A Components Boundary Cooling Water Systems (B.2.3.12)

(Internal)

Pump Casing Leakage Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A77 3.3.1078 A (Reactor Building Pressure Uncontrolled Monitoring of Cooling Water Boundary (External) Mechanical Pumps) Components (B.2.3.23)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 17 of 19 Table 3.3.2-14 Reactor Building Closed Cooling Water - Summary of Aging Management Evaluation Aging Effect Component Intended Aging Management NUREG-2191 Table 1 Material Environment Requiring Notes Type Function Program Item Item Management Pump Casing Leakage Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A (Reactor Building Pressure Cooling Water Systems (B.2.3.12)

Cooling Water Boundary (Internal)

Pumps)

Tanks (Chemical Leakage Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A77 3.3.1078 A Feeder) Pressure Uncontrolled Monitoring of Boundary (External) Mechanical Components (B.2.3.23)

Tanks (Chemical Leakage Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A Feeder) Pressure Cooling Water Systems (B.2.3.12)

Boundary (Internal)

Tanks (Chemical Leakage Carbon Steel Condensation Loss of Material Inspection of Internal VII.E5.A26 3.3.1055 A Feeder) Pressure (Internal) Surfaces in Boundary Miscellaneous Piping and Ducting Components (B.2.3.24)

Tanks (Reactor Leakage Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A77 3.3.1078 A Building Cooling Pressure Uncontrolled Monitoring of Water Surge Tank) Boundary (External) Mechanical Components (B.2.3.23)

Tanks (Reactor Leakage Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A Building Cooling Pressure Cooling Water Systems (B.2.3.12)

Water Surge Tank) Boundary (Internal)

Tanks (Reactor Leakage Carbon Steel Condensation Loss of Material Inspection of Internal VII.E5.A26 3.3.1055 A Building Cooling Pressure (Internal) Surfaces in Water Surge Tank) Boundary Miscellaneous Piping and Ducting Components (B.2.3.24)

Valve Body Leakage Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A77 3.3.1078 A Boundary Uncontrolled Monitoring of (External) Mechanical Components (B.2.3.23)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 18 of 19 Table 3.3.2-14 Reactor Building Closed Cooling Water - Summary of Aging Management Evaluation Aging Effect Component Intended Aging Management NUREG-2191 Table 1 Material Environment Requiring Notes Type Function Program Item Item Management Valve Body Leakage Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A Boundary Cooling Water Systems (B.2.3.12)

(Internal)

Valve Body Leakage Copper Alloy Air Indoor Cracking External Surfaces VIII.H.S454 3.4.1106 A Pressure with Greater Uncontrolled Monitoring of Boundary Than 15% (External) Mechanical Zinc Components (B.2.3.23)

Valve Body Leakage Copper Alloy Air Indoor None None VII.J.AP144 3.3.1114 A Pressure with 15% Uncontrolled Boundary Zinc or Less (External)

Valve Body Leakage Copper Alloy Closed Cycle Loss of Material Closed Treated Water VII.C2.AP199 3.3.1046 A Pressure with 15% Cooling Water Systems (B.2.3.12)

Boundary Zinc or Less (Internal)

Valve Body Leakage Copper Alloy Closed Cycle Loss of Material Closed Treated Water VII.C2.AP199 3.3.1046 A Pressure with Greater Cooling Water Systems (B.2.3.12)

Boundary Than 15% (Internal)

Zinc Valve Body Leakage Copper Alloy Closed Cycle Loss of Material Selective Leaching VII.C2.AP43 3.3.1072 A Pressure with Greater Cooling Water (B.2.3.21)

Boundary Than 15% (Internal)

Zinc Valve Body Leakage Stainless Air Indoor Cracking OneTime Inspection VII.C2.AP209a 3.3.1004 A Pressure Steel Uncontrolled (B.2.3.20)

Boundary (External)

Valve Body Leakage Stainless Air Indoor Loss of Material OneTime Inspection VII.C2.AP221a 3.3.1006 A Pressure Steel Uncontrolled (B.2.3.20)

Boundary (External)

Valve Body Leakage Stainless Closed Cycle Loss of Material Closed Treated Water VII.C2.A52 3.3.1049 A Pressure Steel Cooling Water Systems (B.2.3.12)

Boundary (Internal)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-036 1 Page 19 of 19 Table 3.3.2-14 Reactor Building Closed Cooling Water - Summary of Aging Management Evaluation Aging Effect Component Intended Aging Management NUREG-2191 Table 1 Material Environment Requiring Notes Type Function Program Item Item Management Valve Body Pressure Carbon Steel Air Indoor Loss of Material External Surfaces VII.I.A77 3.3.1078 A Boundary Uncontrolled Monitoring of (External) Mechanical Components (B.2.3.23)

Valve Body Pressure Carbon Steel Closed Cycle Loss of Material Closed Treated Water VII.C2.AP202 3.3.1045 A Boundary Cooling Water Systems (B.2.3.12)

(Internal)